Trinity, Genesis and Kinex implements several published and unpublished vitrinite reflectance models.

LLNL (stands for Lawrence Livermore National Lab where Jerry Sweeney and Alan Burnham worked) model is based on the VITRIMAT model published by Sweeney and Burnham (1989), who a year later (1990) published a simplified version of the model called the "Easy Ro". The "ARCO" model was based on the Falvey and Middleton (1981) model recalibrated to some wells from the Bohai basin. Waples' (1980) model was based on Lopatin's (1971) TTI scheme. The BP models are not published.

Which one is better? It depends on who you ask. These models were calibrated using different data sets and they typically do not give the same prediction for the same thermal history. Remember Vitrinite measurements tend to have large error bars (problems with insufficient count, cavings, suppression, recycling, identification issues, lab differences, etc.). There was significant scatter even fitting the calibration data in the original papers. The fact there are different models means that there is no unique prediction, since there is not even unique measurement. I would treat these models as approximations rather than a precise prediction. You ask two meteorologists about tomorrow's whether, you may get different answers - just live with the uncertainty.

In general, ARCO model seems to work better in younger (Tertiary) basins, while the LLNL model works well in older basins. It may be a good idea to use the same model consistently. The LLNL (or Easy Ro) model is probably used by most people, so I would use it so my results are comparable with others (farm outs, partners etc.). To me, the models are a tool to communicate my source rock maturity estimates to others. I personally would not use it to estimate paleo-heat flow. I wouldn't spend too much time trying to fit a couple of data points - when you get more data points, you will find that you may be just fitting noise.

GOGI stands for gas oil generation index. It is the ratio of gas generation potential divided by oil generation potential (kind like GOR in mass unit). A GOGI of 1.0 means the kerogen generates 50% oil and 50% gas. Gas oil ratios after expulsion will be higher because some oil can not expel as liquid and will crack to gas at higher temperatures. GOGI is typically inversely correlated to hydrogen index (Pepper and Corvi, 1995). You may also see us refer to something called G0 (gee naught), which is the gas generation potential as a fraction of total generation potential. Obviously GOGI = G0/(1-G0).Normally we do not recommend changing the default GOGI for the source rock, it is not so important as gas and oil ratios are mainly controled by the cracking of retained liquid in the source rock. In good source rocks, GOGI is less than 0.2 and in very poor gas prosource rocks GOGI is up to 1.0 (50% of the kerogen converts to oil and 50% to gas).

TI stands for transformation index (an old Rock-Eval term). It is also called BI (bitumen index). It is the S1 peak divided by TOC (S1/TOC*100) therefore in the same unit as HI (Hydrogen Index). It is the hydrocarbons already in liquid/extractable form, therefore kind of indicates the degree of transformation as it may increase with maturity in a good source rock. In a source rock definition in Kinex, we are talking about immature source rock. Therefore TI only represents the pre-existing liquid hydrocarbons in the source rock before generation begins. The quantity is usually insignificant compared to generation potential (HI).Once the source rock is matured enough to have expelled HCs, the S1 measured represents the retained portion. The HCs retained in the rock sample is subject to evaporative loss during drilling and sample storage and preparation, especially at high maturities.

This check box allows us to estimate the degree of cracking of oil in reservoir conditions. If the present day or maximum reservoir temperature is about 150 °C, there is a probability the oil in the reservoir may experience cracking. By checking this box, Kinex assumes the oil in the reservoir is from the type of source rock you entered. The temperature history (min, max temperature and heating rate) is then used to calculate the degree of cracking. The default plot of oil and gas proportions would show the cracking of oil to gas if the temperature is high enough.

The cracking kinetics are dependent on the source rocks that generated the oil, and is based on the Pepper and Corvi 1995 paper.

The coupled source and reservoir feature was designed to model a reservoir that is incased in the source rock. The check box prevents expulsion from happening and models a closed system. This is no longer appropriate for shale plays as we know shales also expel significant about of HCs as well as retaining them. The proper way to model the semi-open system of unocnventional shale plays is described in detail here

This option is for simulating a mixture of different organic matter types in a single source rock. If you are using the default organo-facies by Pepper and Corvi, this is not really necessary, as each depositional environment contains a mixture of different organic matter to some degree. The D/E facies is much a mixture of terrigenous and aquatic (marine or lacustrine) algal material. It is much more appropriate and natural to have layers of different organo-facies, rather than a mixture.